Multi-sensor workflow for evaluation of gas flow in multiple casing strings with distributed sensors

ABSTRACT

A gas presence and distance thereof are calculated using pulsed neutron data. A distance of a gas flow path and a velocity of the gas flow therein are calculated using distributed acoustic sensors. The gas saturation and distance, and gas velocity and distance obtained from the noise data are correlated to obtain a first calculated distance and velocity values. The distance and the velocity of the gas flow are calculated using distributed Doppler sensors. The distance and velocity values are compared with the first calculated distance and velocity values to obtain a second calculated distance and velocity values. The distance of the gas flow and the velocity of the gas flow are calculated using distributed temperature sensors. The distance and velocity values are compared with the second calculated distance and velocity values to determine a distance of a cement interface, and a velocity of a gas flow therein.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. §119 to ProvisionalApplication No. 62/048,479 filed on Sep. 10, 2014, in the United StatesPatent and Trademark Office.

BACKGROUND

Completing an oil or gas well includes a cementing procedure that bondsone or more well casings lining a wellbore to a surrounding subterraneanformation and between each other. In the vast majority of cases, as thewell deepens, new casing strings are needed and cemented in place. Manyother factors can also indicate the need for multiple concentric oroverlapping casing strings, such as compliance with environmental andsafety policies. The cement between these casing strings generallyprevents the presence or movement of fluids within the annular spacesdefined between overlapping casings and between the casing and thewellbore wall. In some wells, the cementing process extends from totaldepth to surface, while in others the cement is present only betweencertain depths.

Of particular importance is the determination of the presence of fluidflow paths in the annular regions defined between overlapping casingsand between the casing and the wellbore wall due to an absence of cement(or cement bond) at or between certain depths. The identification andcharacterization of these flow paths is particularly critical in thecase of plug and abandonment operations, especially in deep waterapplications.

Sonic tools or ultrasonic tools are typically used in the industry toevaluate the cement bonding to both the formation and the casing andhence infer potential annular flow paths (i.e., leaks, channels, gaps,etc.). The evaluation in most of these cases uses raw data from only onesystem of sensors to infer fluid flow parameters through indirectmethods. There is no current workflow method that integrates the variousmeasurements obtained into a borehole model. Current methods are alsotypically used for the characterization of the first casing-cement bond,thereby precluding the evaluation of any subsequent interfaces in thecase of multiple casing strings extended within the well.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, withoutdeparting from the scope of this disclosure.

FIG. 1A is a well system that can employ the principles of the presentdisclosure.

FIG. 1B is a cross-sectional end view of an exemplary cable.

FIG. 2 depicts an enlarged cross-sectional view of a portion of thewellbore of FIG. 1A.

FIG. 3 illustrates a semi-descriptive borehole model derived from pulsedneutron log data.

FIG. 4 illustrates a semi-descriptive borehole model derived fromoptical fiber measurements obtained from the distributed acousticsensors of FIGS. 1A and 1B.

FIG. 5 illustrates a semi-descriptive borehole model derived from dataobtained from the distributed Doppler sensors of FIGS. 1A and 1B.

FIG. 6 denotes the borehole model derived from an integrated workflowmethod.

FIG. 7 is a flowchart schematic of an exemplary workflow method toidentify and characterize fluid flow at cement interfaces in a wellbore.

DETAILED DESCRIPTION

The present disclosure is related to the field of production ofhydrocarbons from wellbores and, more particularly, to methods ofevaluating annular flow of gas between multiple casing strings that linea wellbore and between a wellbore wall and the casing strings.

The present disclosure describes integrated workflow methods thatindicate the location and flow rate of gas between overlapping sectionsof casings in a wellbore, and between the wellbore wall and the casing.The methods and systems described herein are applicable in wellboreslined with multiple casing strings and use a pulsed neutron sensor,distributed acoustic sensors (DAS), distributed Doppler sensors (DDS),and distributed temperature sensors (DTS). Embodiments of the presentdisclosure provide more direct and accurate measurements of cement bondquality and cement sheath characterization using the aforementionedsensors. The methods described herein help enhance the evaluation andcharacterization of cement sheaths without requiring investment in newtools, new tool hardware, or adaptations of existing tools.

FIG. 1A is an exemplary well system 100 that may employ the principlesof the present disclosure. As illustrated, a wellbore 102 has beendrilled from a surface location 104 into a subterranean formation 106that may contain hydrocarbons. Set within the wellbore 102 is at leastone string of casing 108 bonded to the inner wall of the wellbore 102with cement 110. While not expressly shown, the casing 108 may comprisemultiple strings of casing secured within the wellbore 102, whereaxially adjacent casings 108 overlap each other at least a shortdistance.

The casing 108 is bonded within the wellbore 102 by adding the cement110 within an annulus 111 formed between the outer diameter of thecasing 108 and the inner diameter of the wellbore 102. The resultingcement bond not only adheres the casing 108 within the wellbore 102, butalso serves to isolate adjacent zones (112 a and 112 b) within theformation 106 from one another. Isolating the adjacent zones 112 a,b canbe important when one of the zones 112 a,b contains oil or gas and theother zone includes a non-hydrocarbon fluid, such as water. Should thecement 110 surrounding the casing 108 be defective and fail to provideisolation of the adjacent zones 112 a,b, gas, water, or otherundesirable fluid can migrate into the hydrocarbon producing zone, thusdiluting or contaminating the hydrocarbons within the producing zone.The cement 110 also serves to bond axially adjacent casings 108 thatoverlap each other a short distance (e.g., concentric casings).

To detect possible defective cement bonds between the casing 108 and thewellbore 102 and between overlapping lengths of the casing 108, a toolstring 114 may be introduced into the wellbore 102 on a conveyance suchas a cable 126. In some embodiments, the cable 126 and the conveyancemay comprise the same structure. In other embodiments, however, theconveyance and the cable 126 may not be the same and the cable 126 mayinstead be strung along the length of the conveyance, but not used tolower the tool string 114 into the wellbore 102. In yet otherembodiments, the cable 126 may alternatively be attached to the outersurface of the casing 108 in the annulus 111. Other suitable conveyancescan include, however, drill pipe, coiled tubing, a downhole tractor,production tubing, and the like. In some embodiments, the cable 126 maybe connected to a surface processing unit 118, which is depicted in FIG.1A as a truck, via a pulley system 120 and fed into the wellbore 102 viaa wellhead installation 122, such as a lubricator or the like.

The tool string 114 may include one or more logging tools or sensorssuch as, a pulsed neutron sensor 124, developed for analyzing theintegrity of the cement 110 bonding the casing 108 to the wellbore 102and/or to a portion of an overlapping casing (not shown). In someembodiments, the cable 126 may incorporate one or more optical fibers toobtain distributed and/or point measurements of one or more wellparameters also for analyzing the integrity of the cement 110 bondingthe casing 108 to the wellbore 102 and/or to a portion of an overlappingcasing.

The cable 126 may be configured for optical fiber sensing to obtainpoint or distributed optical fiber measurements. As used herein,“distributed optical fiber sensing” refers to the ability to obtain wellparameter measurements along the entire length of an optical fiber, butalso refers to the ability to obtain point measurements from pointreflectors (e.g., Fiber Bragg Gratings, etc.) included at predeterminedlocations along the optical fiber(s).

According to the embodiments of the present disclosure, the opticalfibers in the cable 126 may be used as distributed acoustic sensors(DAS), distributed Doppler sensors (DDS), and/or distributed temperaturesensors (DTS). In an example, one or more optical fibers may be used foreach of DAS, DDS, and DTS.

A number of distributed optical fiber sensing methodologies may be usedto determine the well parameters of interest, without departing from thescope of the present disclosure. When electromagnetic radiation istransmitted through an optical fiber, a portion of the electromagneticradiation will be backscattered in the optical fiber by impurities ofthe optical fiber, areas of different refractive index in the fibergenerated in the process of fabricating the fiber, interactions with thesurfaces of the optical fiber, and/or connections between the fiber andother optical fibers or components. Some of the backscatteredelectromagnetic radiation is treated as unwanted noise and steps may betaken to reduce such backscattering.

DAS is typically based on coherent Rayleigh scattering where an opticalfiber is optically coupled with (i.e. in optical communication with) anarrow-band electromagnetic radiation source, such as a narrow-bandlaser or the like. The laser may be used to produce short pulses oflight that are launched into the optical fiber and a fraction of thebackward scattered light that falls within the angular acceptance coneof the optical fiber in the return direction, i.e., towards the lasersource, may be guided back to the launching end of the fiber as abackscattered signal. The backscattered signal may be used to provideinformation regarding the time varying state of strain along the opticalfiber, which may be equated to locations where fluctuations in acoustic(vibration) is occurring. In the surface processing unit 118, adetector, such as an optoelectronic device may be in opticalcommunication with the optical fiber(s) in the cable 126 and used toconvert the backscattered electromagnetic signals to electrical signals,and a signal processor of the surface processing unit 118 may processthe electrical signals to determine the magnitude of the strain assumedby the optical fiber downstream of the detector.

DTS is typically based on distributed Raman scattering to detect changesin temperature along the optical fiber. More specifically, fluctuationsor changes in temperature can affect the glass fibers of an opticalfiber and locally change the characteristics of light propagation in theoptical fiber. Because of a temperature-dependent nonlinear processcalled Raman scattering, the location and magnitude of a temperaturechange can be determined so that the optical fiber can be used as alinear thermometer.

DDS functions based on the Doppler effect observed because of flowingfluid. An acoustic source located in the wellbore emits acoustic wavesof different frequencies into the wellbore. The acoustic waves interactwith fluid flowing in the wellbore and are attenuated. For instance, thehigher frequency waves may be attenuated by fluid flowing closer to theoptical fiber and lower frequency waves may be attenuated by fluidflowing further away from the optical fiber. The attenuated acousticwaves impinge upon an optical fiber positioned in the wellbore. Theattenuated waves induce varying amount of strain in the optical fiberdepending on the frequency. Interferometric techniques may be used toanalyze the strain induced in the fiber and a location of the flowingfluid.

FIG. 1B is a cross-sectional end view of an exemplary cable 126. Thecable 126 may comprise a variety of types, sizes, and/or designs, eachof which contains one or more optical fibers included and otherwiseembedded therein. For example, the cable 126 may comprise a braidedcable containing one or more optical fibers, or a hollow tube made ofmetal, plastic, or a composite and containing one or more opticalfibers. The cable 126 may also include electrical conductors used forconveying data and/or power to the tool string 114. It will beappreciated, however, that additional types or designs of the cable 126incorporating optical fibers may alternatively be employed. Accordingly,the types of cable 126 suitable for the present application should notbe limited to those specifically mentioned herein.

In some embodiments, as illustrated, the cable 126 may include a sheath130 disposed about a polymer composite 132. The sheath 130 acts as aprotective coating for the polymer composite 132 to mitigate damage tothe polymer composite 132 or components thereof during operation. Insome instances, however, the sheath 130 may be excluded from the cable126. The sheath 130 may be made of a metal material or another polymerwith better performance with respect to properties includinganti-wearing, hermetical sealing, and high mechanical strength. Thepolymer composite 132 may comprise a polymer matrix with a plurality offibers embedded therein to provide desirable mechanical strength.

The cable 126 may further include one or more optical fibers 134 (threeshown) embedded within the polymer composite 132 and extending along allor a portion of the length of the cable 126. The optical fibers 134 maybe useful for obtaining distributed acoustic, Doppler, and/ortemperature measurements along the length of the optical fibers 134. Theoptical fibers 134 may be low-transmission loss optical fibers that areeither single-mode or multi-mode. In some instances, the optical fibers134 may have a coating or a cladding 136 disposed thereon or otherwiseencapsulating the optical fibers 134. The cladding 136 may be ahigh-temperature coating made of, for example, a thermoplastic material,a thermoset material, a metal, an oxide, carbon fiber, or anycombination thereof. The cladding 136 may improve the mechanical bondingstrength of the optical fibers 134 to the polymer composite 132, reducethermal expansion mismatch between the optical fibers 134 and thematerials of the polymer composite 132, and/or provide a hermetic sealthat protects the optical fibers 134 from moisture and/or hydrogen thatmight induce artificial signal attenuation by hydroxyl ion or molecularhydrogen absorption.

In other embodiments, the optical fibers 134 may each be sealed andotherwise loosely housed within a hollow or “loose” tube 138 andotherwise embedded within the polymer composite 132. The loose tube 138provides an elongated housing for the optical fibers 134 but alsoisolates the optical fibers 134 from tensile stresses or strains thatmay be assumed by the polymer composite 132 during downhole deploymentand operation.

As illustrated, the cable 126 may also include one or more (two shown)electrical conductors 146 embedded within the polymer composite 132 andextending along the length of the cable 126. The electrical conductors146 may supply electrical power and/or facilitate communication betweenthe tool string 114 (FIG. 1A) and the surface processing unit 118 (FIG.1A). The electrical conductors 146 may be sealed and otherwise looselyhoused within a tubing 148 that provides an elongated housing for theelectrical conductors 146 and protects the electrical conductors 146from tensile stresses or strains that may be assumed by the polymercomposite 132 during operation.

Returning to FIG. 1A, with the cable 126 extended in the wellbore 102,measurements along the length of the cable 126 or at selected points maythen be obtained to determine one or more well parameters. The opticalfiber(s) 134 (FIG. 1B) embedded within the cable 126 may be in opticalcommunication at the surface with a data processing unit 160 located onboard the surface processing unit 118. The data processing unit 160 mayinclude an electromagnetic radiation source 140 and a data acquisitionsystem 142.

The electromagnetic radiation source 140 may be configured to emit andotherwise introduce electromagnetic radiation into the optical fiber(s)134. The electromagnetic radiation source 140 may include, but is notlimited to, ambient light, a light bulb, a light emitting diode (LED), alaser, a blackbody radiator source, a supercontinuum source,combinations thereof, or the like. Accordingly, the electromagneticradiation may include, but is not limited to, terahertz, infrared andnear-infrared radiation, visible light, and ultraviolet light.

The data acquisition system 142 may include one or more detectors 144positioned to sense and otherwise monitor the intensity of the returningbackscattered electromagnetic radiation for analysis. The detector 144may be an optical transducer. The detector 144 may comprise, but is notlimited to, a thermal detector (e.g., a thermopile or photoacousticdetector), a semiconductor detector, a piezo-electric detector, a chargecoupled device (CCD) detector, a photodetector, a video or arraydetector, a split detector, a photon counter detector (such as aphotomultiplier tube), any combination thereof, or any other detectorsknown to those skilled in the art.

The data acquisition system 142 may further include a signal processoror signal analysis equipment associated with the detector 144, which mayinclude a standard optical spectral analyzer having a processor forprocessing, storing in a computer-readable storage medium for storing aprogram code executed by the processor, and displaying to a user thedetected results. Examples of a computer-readable storage medium includenon-transitory medium such as random access memory (RAM) devices, readonly memory (ROM) devices, optical devices (e.g., CDs or DVDs), and diskdrives. The signal analysis equipment is capable of converting thereceived signals into an electronic signal, such as a high-speed linearphotodetector array, a CCD array, or a CMOS array. In some embodiments,the processor may be provided with a user interface for input andcontrol, such as by generating reports and performing fast Fouriertransform analyses. In at least one embodiment, the data acquisitionsystem 142 may be configured to provide acoustic, Doppler, andtemperature logs of the entire length of the wellbore 102 so that a welloperator can analyze the presence, location, and flow rate of gasbetween the casing 108 and the formation 106 and between overlappingsections of the casing 108.

The backscattered electromagnetic radiation measured by the detector 144may be correlated to strain (dynamic and static) and temperatureprofiles sensed by the cable 126, which may be indicative of gas flowbetween the surrounding formation 106 and the wellbore 102 and/orbetween overlapping sections of the casing 108. Since the speed of lightis, at first approximation, constant along optical fibers, the distancefrom the surface to the point where the backscatter originated can alsobe readily determined when the effective refractive index of thecombined fiber core and cladding is known (e.g., about 1.468 at 1550nm). Accordingly, backscatter generated within the optical fiber(s) 134(FIG. 1B) as measured by the detector 144 may indicate the position ofgas flow between the surrounding formation 106 and the wellbore 102and/or between overlapping sections of the casing 108. After a fewseconds or minutes of data gathering, noise, Doppler, and temperaturelogs of the entire wellbore 102 can be generated by the data acquisitionsystem 142 and subsequently analyzed to determine the presence andlocation of flows between the surrounding formation 106 and the wellbore102 and/or between overlapping sections of the casing 108.

The electrical conductors 146 (FIG. 1B) may be in electrical connectionwith a power source 150 included in the surface processing unit 118 thatprovides electrical power to the pulsed neutron sensor 124. Theelectrical conductors 146 may also be connected to the data acquisitionsystem 142 that provides control/command signals to manage the operationof the pulsed neutron sensor 124. For instance, the control/commandsignals may be provided by a processor included in the data acquisitionsystem 142 and capable of processing instructions stored in acomputer-readable storage medium coupled thereto.

FIG. 2 depicts an enlarged cross-sectional view of a portion of thewellbore 102 of FIG. 1A lined with a first casing 108 a and a secondcasing 108 b. A first cement layer 110 a is disposed within a firstannulus 202 a defined between the outer diameter of the first casing 108a and the inner diameter of second casing 108 b. A second cement layer110 b is disposed within a second annulus 202 b defined between theouter diameter of the second casing 202 and the formation 106. The firstand second cement layers 110 a,b disposed within the first and secondannuli 202 a,b, respectively, bond the first and second strings ofcasing 108 a,b to the surrounding formation 106 and to each other.

A first cement interface 206 a is provided at the outer diameter of thefirst casing 108 a and the first cement layer 110 a. A second cementinterface 206 b is provided at the inner diameter of the second casing108 b and the first cement layer 110 a. A third cement interface 206 cis provided at the outer diameter of the second casing 108 b and thesecond cement layer 110 b, and a fourth cement interface 206 d isprovided at the inner diameter of the formation 106 and the secondcement layer 110 b. FIG. 2 also depicts one or more potential gaps orinterface flow paths 208 (shown as interface flow paths 208 a, 208 b,208 c, and 208 d). A fluid, such as gas, may be able to traverse one ormore of the various interface flow paths 208 a-d. According to thepresent disclosure, the pulsed neutron sensor 124 (FIG. 1A), thedistributed acoustic sensors (DAS), the distributed Doppler sensors(DDS), and the distributed temperature sensors (DTS) obtained from theoptical fibers 134 (FIG. 1B) may be cooperatively used to identify andcharacterize the cement interfaces 206 a-d and thereby determine ifthere is any fluid flow at or adjacent the interface flow paths 208 a-d.

In operation, and in an integrated workflow method, the tool string 114including the pulsed neutron sensor 124 may be lowered to a desireddepth generally along the center of the wellbore 102. High-energyneutrons are emitted by a neutron source (not expressly illustrated)located on the tool string 114 into the wellbore 108 and the formation106. Because gas has low density, there are relatively fewer collisionsbetween the gas molecules and the neutrons, and a relatively highernumber of neutrons are received back by the pulsed neutron sensor. Fromthe number of neutrons received, a count rate (e.g., number of neutronsreceived per unit time) of the neutrons is obtained.

The pulsed neutron sensor 124 may generate a pulsed neutron log from thecount rate. The pulsed neutron log may be analyzed to obtain pulsedneutron log (PNL) data including a value of gas saturation within theradius of investigation of the pulsed neutron sensor 124. The gassaturation is provided to a model that determines (or predicts) thelocation of the gas (or the gas zone) in the wellbore 102 (for instance,in one or more interface flow paths 208 a-d) and the radial distance ofthe gas zone from center of the wellbore 102 (or, alternatively, theradial distance from the tool string 114).

It should be noted that the count rate also can be used to make aninitial determination whether water or gas is present in the interfaceflow paths 208 a-d defined by the first casing 108 a and the secondcasing 108 b. As is known, the neutron absorption in water is muchhigher than in gas. Therefore, if the count rate is high, it can then bedetermined that gas is present. However, if the count rate is small,then it can be determined that water is present in the wellbore 108.

FIG. 3 illustrates an exemplary semi-descriptive borehole model 300derived from pulsed neutron log (PNL) data obtained from the pulsedneutron sensor 124 (FIG. 1A). As used herein, the term “semi-descriptiveborehole model” indicates that the model (for instance, a mathematicalmodel) may not be an exact representation of the wellbore, butcharacterizes the wellbore 102 with a level of accuracy adequate fordetermining any gas presence in the wellbore 102. The measurementobtained from the pulsed neutron sensor is considered a staticmeasurement since the PNL data determines the saturation of gas thatdoes not have to be flowing. The pulsed neutron log (PNL) borehole model300 characterizes the wellbore 102, and, when provided with the PNLdata, determines (or predicts) the presence of gas in the wellbore 102and the radial distance of the gas zone from center of the wellbore 102.

For instance, as illustrated, the model 300 characterizes the wellbore102 as being lined with a first casing 308 a and a second casing 308 b.The first casing 308 a may characterize the first casing 108 a (FIG. 2)and the second casing 308 b may characterize the second casing 108 b(FIG. 2). A first region 310 a, characterizing the first cement layer110 a (FIG. 2), is defined between the first casing 308 a and the secondcasing 308 b. A second region 310 b may be defined adjacent the secondcasing 308 b. The second region 310 b may collectively represent thesecond cement layer 110 b and the formation 106 in FIG. 2.

The pulsed neutron sensor 124 cannot distinguish between the secondcement layer 110 b (FIG. 2) and the formation 106 (FIG. 2) if no gap ispresent or if the well is shut-in. In other words, the pulsed neutronsensor 124 may not be able to determine the presence of the fourthinterface 206 d (FIG. 2) if no gap is present or if there is no gaspresent in the gap while the measurement is taking place. However, ifflow path 208 d (FIG. 2) is present and includes gas, the fourthinterface 206 d may be detected by the pulsed neutron sensor 124, and,as a result, the model 300 is able to characterize the fourth interface206 d and the corresponding gas flow 312 d.

From the PNL data obtained, the model 300 predicts the presence of gasin one or more flow paths 312 a-d and the radial distance of the gaszone. It should be noted that, due to the limitation in the resolution,the pulsed neutron sensor 124 also may not distinguish the flow 312 b(at the interface 206 b, FIG. 2) from the flow path 312 c (at theinterface 206 c, FIG. 2). Thus, the model 300 assumes the flow paths 312b,c to be at the same radial distance from the center of the wellbore102. It will be understood that the number of flow paths illustrated inFIG. 3 is merely an example and the number of flow paths may increase ordecrease depending on the PNL data provided to the model 300.

The DAS formed by one or more of the optical fibers 134 (FIG. 1B) of thecable 126 (FIGS. 1A and 1B) may be configured to “listen” to the noisegenerated due to gas flow in the one or more flow paths 312 a-d, andgenerate a corresponding noise log (NL). The acoustic wave (or signal)generated due to the noise of the gas flow may impinge upon the opticalfiber(s) 134 causing the optical fiber(s) 134 to strain. Thebackscattered signal may be used to provide information regarding thetime varying state of strain along the optical fiber(s) 134, which maybe equated to locations where the acoustic wave was generated. The noiselog generated by the data acquisition system 142 (FIG. 1A) may beanalyzed to obtain noise log data including an amplitude of a noisesignal generated by each of the one or more gas flows, a frequencyspectrum of the noise signals generated, a relative phase shift betweenthe noise signals, frequency ratios of the near and far noise signals,and power spectral density of the noise signals. The amplitude andfrequency information obtained may be provided to a DAS borehole modelthat determines (or predicts) the velocity of the gas in each flow path312 a-d determined to be present in the wellbore and the radial distanceof each flow path from the center of the wellbore 102 (or,alternatively, the radial distance from the tool string 114).

FIG. 4 illustrates an exemplary semi-descriptive DAS borehole model 400derived from NL data generated by the data acquisition system 142 (FIG.1A) using the distributed acoustic sensors (DAS). The measurementsobtained from the DAS are referred to as dynamic measurements sincenoise can be generated by the gas only when the gas is flowing. The DASand the pulsed neutron sensor 124 (FIG. 1A) obtain data from the samewellbore 102 and at approximately the same distance. Accordingly,similar physical phenomena (the gas flow or the gas presence, forinstance) are measured by the pulsed neutron sensor 124 and the DAS atsimilar distances. Further, the pulse neutron sensor 124 and the DAS mayeach have similar resolution limitations and similar depth ofinvestigation. The DAS borehole model 400 may be similar in somerespects to the model 300 in FIG. 3, and therefore may be bestunderstood with reference thereto where like numerals designate likecomponents not described again in detail. The model 400 may characterizethe wellbore 102, and, when provided with the NL data, may predict thevelocity of the gas flow in the one or more flow paths 312 a-d and theradial distance of the gas flow from the center of the wellbore 102.

The model 400 may determine the radial distance from the amplitudeinformation. For instance, the amplitude of a noise signal generated bya gas flow close to the cable 126 is larger than the amplitude of anoise signal generated by a gas flow further away from the cable 126.From the frequency information, the model 400 predicts the width of theflow path through which the gas flows, and the velocity of the gas flow.For instance, a higher frequency may indicate a flow path 312 a-d havinga smaller width and gas flowing with a higher velocity, and a lowerfrequency may indicate a flow path 312 a-d have a larger width and gasflowing with a relatively smaller velocity.

Accordingly, based on the NL data provided, the model 400 determines theradial distance of the one or more flow paths 312 a-d and the velocityof the gas flow in each of the flow paths 312 a-d. Since the measurementby the DAS is a dynamic measurement, based on the NL data obtained, itmay not be possible to distinguish between the second cement layer 110 b(FIG. 2) and the formation 106 (FIG. 2) if no gap is present or if thewell is shut-in. In other words, the data acquisition system 142 may notbe able to determine the presence of the fourth interface 206 d (FIG. 2)if no gap is present or if there is no gas flow in the gap whilemeasurement is being performed. However, if the flow path 208 d ispresent and the gas is flowing, the fourth interface 206 d may bedetected (for instance, by the data acquisition system 142), and themodel 400 is able to characterize the fourth interface 206 d and the gasflow 312 d. It will be understood that the number of flow pathsillustrated in FIG. 4 is merely an example, and the number of flow paths312 a-d may be more or less depending on the NL data provided to themodel 400.

The velocity of the gas flow in one or more flow paths 312 a-d and theradial distance of the gas flow as predicted by the model 400 arecorrelated with the gas saturation in one or more flow paths 312 a-d andthe radial distance of the gas as predicted by the model 300. Thepredictions from the models 300 and 400 may be determined to conform toeach other when, for instance, the gas velocity as predicted by themodel 400 is in accordance with the gas saturation as predicted by themodel 300. For instance, based on the measured frequency and amplitudeof the noise generated due to the gas flow, the gas flow may be assumedto be present at a certain distance. Based on the gas saturation, acertain width of the flow path that would create the measured frequencyand amplitude of the noise is then assumed. The above parameters may bere-calculated or refined based on an iterative calculation process (andalso may be re-calculated or refined based on the predictions obtainedfrom the other models, detailed below). When these parameters lie withinthe margin of error of each other (and with the predictions from theother models), then the predictions from the models 300 and 400 may bedetermined to conform to each other. If the predictions do not conform,the model 300 and/or the model 400 may be updated. Updating the models300, 400 may entail recalculating one or more of the gas saturation, thevelocity of the gas flow in each flow path 312 a-d, and the radialdistance of the gas in the flow paths 312 a-d. The process may berepeated iteratively until predictions by the models 300 and 400 conformto each other, thereby resulting in first calculated values of thevelocity of each gas flow and the radial distance of each flow path 312a-d. From the above, it will thus be understood that thecharacterization of the flow paths 312 a-d in FIGS. 3 and 4 by therespective models 300, 400 may be subject to change based on theabove-mentioned comparison operation and the subsequent calculationsperformed by the models 300 and 400.

The DDS formed by one or more of the optical fibers 134 (FIG. 1B) of thecable 126 (FIGS. 1A and 1B) may receive an acoustic wave modified by theformation 106 and the wellbore 102. A Doppler log is generated by thedata acquisition system 142 based on the modified acoustic wavereceived. The Doppler log is analyzed to obtain Doppler log dataincluding the amplitude and frequency of the modified acoustic wave, andthe Doppler frequency shift between the emitted acoustic wave and themodified acoustic wave. The Doppler log data may be provided to a DDSborehole model that determines (or predicts) the velocity of the gasflow in each flow path determined to be present in the wellbore 102 andthe radial distance of each flow path from center of the wellbore 102(or, alternatively, the radial distance from the tool string 114). Itshould be noted that wellbore measurements using the DDS may be used toconfirm the presence of gas. This is because, negligible Doppler effectis observed in gas, and, therefore the acoustic wave may be modifiedminimally and the frequency shift observed may be minimal. If, however,a relatively greater frequency shift is observed, it may be determinedthat water is present in the wellbore.

FIG. 5 illustrates an exemplary semi-descriptive DDS borehole model 500derived from Doppler log data generated by the data acquisition system142 using the distributed Doppler sensor (DDS). The measurementsobtained from the DDS are referred to as dynamic measurements sinceDoppler effect can be seen only when the gas is flowing. Like the pulsedneutron sensor 124 and the DAS, the DDS also obtains measurement datafrom the same wellbore 102 at approximately the same distance as thepulsed neutron sensor 124 and DAS. Accordingly, similar physicalphenomena (the gas flow or gas presence, in this case) are measured bythe pulsed neutron sensor 124, the DAS, and the DDS at similardistances. Further, the pulse neutron sensor 124, the DAS, and the DDSmay each have similar resolution limitations and similar depth ofinvestigation. The DDS borehole model 500 may be similar in somerespects to the models 300 and 400 in FIGS. 3 and 4, respectively, andtherefore may be best understood with reference thereto where likenumerals designate like components not described again in detail.

Similar to model 400, the model 500 may characterize the wellbore 102and, when provided with the Doppler log data from the data acquisitionsystem 142, may predict the velocity of the gas flow in each flow path312 a-d and the radial distance of each flow path 312 a-d from thecenter of the wellbore 102. Since the measurement performed by the DDSis a dynamic measurement, based on the Doppler log data obtained, it maynot be possible to distinguish between the second cement layer 110 b(FIG. 2) and the formation 106 (FIG. 2) if no gap is present or if thewell is shut-in. In other words, the data acquisition system 142 may notbe able to determine the presence of the fourth interface 206 d (FIG. 2)if no gap is present or if there is no flow in the gap while themeasurement is taking place. However, if the flow path 208 d is presentand the gas is flowing, the fourth interface 206 d may be detected bythe data acquisition system 142, and, as a result, the model 500 is ableto characterize the fourth interface 206 d (FIG. 2) and the gas flow 312d. It will be understood that the number of flow paths 312 a-dillustrated in FIG. 5 is merely an example, and the number of flow paths312 a-d may be more or less depending on the Doppler log data providedto the model 500.

A comparison operation may be performed, wherein the velocity of the gasflow in each flow path 312 a-d and the radial distance to each flow path312 a-d as predicted by the model 500 are compared with the firstcalculated values of the velocity of the gas flow in each flow path 312a-d and the radial distance of the flow paths 312 a-d obtained from thefirst comparison operation. If the predictions by the model 500 do notmatch the first calculated values of velocity of the gas flow in eachflow path 312 a-d and the radial distance of the flow paths 312 a-d, oneor more of the models 300, 400, and 500 may be updated. Updating themodels 300, 400, and 500 may entail recalculating one or more of the gassaturation, the velocity of the gas flow in each flow path 312 a-d, andthe radial distance of the flow paths 312 a-d. The process repeatsiteratively until the first calculated values of the velocity and theradial distance of the gas flow match the velocity and the radialdistance of the gas flow obtained by the model 500, thereby resulting insecond calculated values of the velocity of gas flow and the radialdistance of each flow path 312 a-d. From the above, it will thus beunderstood that the characterization of the flow paths 312 a-d in FIGS.3, 4, and 5 by the respective models 300, 400, and 500 is subject tochange based on the above-mentioned comparison operation and thesubsequent calculations performed by the models 300, 400, and 500.

The wellbore 102 may be characterized using a static borehole model. Thestatic borehole model is constructed based on a completed wellbore 102and includes data obtained from drilling and completion operations, loganalysis, cuttings, casing specifications, cement specifications, bitsize, caliper, tubing size, formation properties—lithology, porosity,gas saturation, water saturation, etc., acoustic impedance of the casingand cement, heat capacity of the casing and cement, noise andtemperature conduction in the casing, cement, and formation, specificvelocity of sounds casing, cement, and formation, and the like. Usingthe static borehole model, a DTS borehole model is obtained. The DTSborehole model is provided with temperature data obtained using thetemperature sensor 124 d.

The data acquisition system 142 obtains the temperature of the formation106 and the wellbore 102 using the DTS formed by one or more of theoptical fibers 134 (FIG. 1B) of the cable 126 (FIGS. 1A and 1B), andcreates a temperature profile based on the obtained temperatureinformation. The measurements obtained by the DTS are considered aspseudo-dynamic measurements, since these measurements are obtained basedon gas that was flowing in the past and may be not be flowing at thetime of measurement. The temperature profile includes a variation in thetemperature due to one or more gas flows at the time of measurement andtemperature variations due to one or more gas flows that occurred duringa predetermined time interval in the past. This predetermined timeinterval may occur any time between the plug and abandonment operationof the well and the time the temperature is measured. The temperaturevariations may be caused due to a higher temperature gas flow from adownhole location. For instance, since temperature in the sub-surfaceincreases with depth, gas flowing from a downhole location to an upholelocation will increase the temperature at the uphole location. Further,heat will be generated due to friction of the gas flow with thesurroundings, which will also contribute to temperature increase. Fromthe temperature profile, temperature data including the temperaturevalue at a given depth (e.g., the amplitude of the temperature profileat a given time), the temperature gradient (the rate of increase intemperature with depth), and a derivative of the temperature profile maybe obtained.

The temperature data from the data acquisition system 142 may beprovided to a DTS borehole model that determines (or predicts) thevelocity of the gas flow in each flow path 312 a-d determined to bepresent in the wellbore 102 and the radial distance of each flow path312 a-d from the center of the wellbore 102 (or, alternatively, theradial distance from the tool string 114). The DTS borehole model may besimilar to any one of the above-disclosed models 300, 400, and 500, andthe operation thereof may be understood with respect to the operation ofany of the models 300, 400, and 500, as disclosed above. However, unlikethe models 300, 400, 500, the DTS borehole model may be able tocharacterize the fourth interface 206 d (FIG. 2) and the gas flow 208 d(FIG. 2) even when the measurement is performed with the well shut-in.This is because, from the temperature profile and the static boreholemodel, the DTS borehole model may determine that any temperaturevariation detected while the well is shut-in, but not detected eitherbecause the variation is beyond the depth of investigation of the pulsedneutron sensor 124, the DAS, and the DDS, or because the variationoccurred while the gas was flowing, has to be occurring due to apresence of a gas flow at the fourth interface 206 d.

The velocity of the gas flow and the radial distance to each flow pathas predicted by the temperature borehole model are compared with thesecond calculated values of the velocity of the gas flow in each flowpath and the radial distance of each flow path 312 a-d obtained above.If the predictions by the DTS borehole model do not match the secondcalculated values of the velocity of the gas flow in each flow path andthe radial distance of the flow paths, one or more of the models 300,400, 500, and the DTS borehole model may be updated. Updated the models300, 400, 500, and the DTS borehole model may entail recalculating oneor more of the gas saturation, the velocity of the gas flow in each flowpath, and the radial distance of the flow paths. The process repeatsiteratively until the velocity and the radial distance of the gas flowmatch the velocity and the radial distance of the gas flow obtained bythe DTS borehole model, thereby resulting in the widths of the flowpaths 312 a-d at the cement interfaces 206 a-d, the velocity of the gasflow in each of the flow paths 312 a-d, and the radial distance to thegas flow.

According to embodiments disclosed above, the models 300, 400, 500, andthe DTS borehole model characterize the wellbore 102 and the surroundingregions assuming that the cable 126 including the optical fiber(s) 134is located generally along the center of the wellbore 102, asillustrated in FIG. 1A. However, it will be understood that, if thecable 126 is positioned in the annulus 111 or any other region of thewellbore 102, different borehole models may be used to characterize thewellbore 102 and the surrounding regions.

FIG. 6 illustrates a static and dynamic borehole model 600 derived fromthe above-described integrated workflow method for evaluating annularflow of gas between multiple casing strings. The borehole model 600 maybe best understood with reference to FIG. 2, where like numeralsdesignate like components not described again in detail. The boreholemodel 600 may be referred to as a descriptive model since the model 600may be a near exact representation of the wellbore 102 illustrated inFIG. 2. Using the borehole model 600, for example, it may thus bepossible to determine the widths of the flow paths 208 a-d at the cementinterfaces 206 a-d, the velocity of the gas flow in each of the flowpaths 208 a-d, and the radial distance to the gas flow with relativelyhigh accuracy.

FIG. 7 is a flowchart schematic of an exemplary integrated workflowmethod 700 for determining the presence of a presence of gas, the radialdistance to the gas zone, and the velocity of the gas flow in awellbore. It should be noted that methods consistent with the presentdisclosure may include at least some, but not all of the activities(steps) illustrated in method 700, performed in a different sequence.

The method 700 may include obtaining a pulsed neutron log (PNL) from thepulsed neutron sensor 124 (FIG. 1A), as at 702. The method 700 thenextracts (e.g., via deconvolution) PNL data including an amount of gassaturation in the wellbore, as at 704. As at 705, the PNL data isprovided to a PNL borehole model (obtained at 706). The PNL boreholemodel may be similar to or the same as the model 300 illustrated in FIG.3 and, when provided with the PNL data, the PNL borehole model predictsthe presence of gas in the wellbore as characterized by the PNL boreholemodel and a first radial distance of the gas zone from center of thewellbore 102, as at 708.

A noise log (NL) is obtained from the data acquisition system 142 (FIG.1A) using the DAS formed by one or more of the optical fibers 134 (FIG.1B), as at 722. The method 700 then obtains (e.g., via deconvolution) NLdata including one or more of the amplitudes of the noise signals, afrequency spectrum of the noise signals, a relative phase shift betweenthe noise signals, frequency ratios of the near and far noise signals,and power spectral density of the noise signals, as at 724. The method700 provides a DAS borehole model, as at 726. The DAS borehole model maybe similar to the model 400 illustrated in FIG. 4, and is provided theNL data, as at 725. Based on the NL data, the DAS borehole modeldetermines a second radial distance of the one or more flow paths havinggas from center of the wellbore 102 and a first velocity value of thegas flow in each of the one or more flow paths, as at 728.

At 710, the gas saturation and the first radial distance of the flowpaths are correlated with the second radial distance of the flow pathsand the first velocity value. If gas saturation and the first radialdistance predicted by the PNL borehole model do not conform to the firstvelocity value and the second radial distance predicted by the noise logborehole model, the PNL borehole model (706) and/or the noise logborehole model (726) are updated, as at 712. One or more of the gassaturation, the first and second radial distances, and the firstvelocity value are recalculated based on an updated PNL borehole model(706) and/or updated noise log borehole model (726).

If the gas saturation and the first radial distance predicted by the PNLborehole model conform to the first velocity value and the second radialdistance predicted by the noise log borehole model, a first result isobtained, as at 714. The first result includes the radial distance ofthe one or more flow paths in the wellbore 102 and the velocity of thegas flow in the one or more flow paths.

At 742, a Doppler log is obtained from the data acquisition system 142(FIG. 1A) using the distributed Doppler sensors (DDS) and, at 744,Doppler data including an amplitude and frequency information of themodified acoustic wave, and the Doppler frequency shift is extracted(e.g., via deconvolution) from the Doppler log. As at 745, the method700 provides the Doppler data to the DDS borehole model, which isobtained at 746. The DDS borehole model may be similar to the model 500illustrated in FIG. 5, and, when provided with the Doppler data, the DDSborehole model determines third radial distance of the one or more flowpaths from center of the wellbore 102 and a third velocity value of thegas flow in each of the one or more flow paths, as at 748.

At 730, the third radial distance and the second velocity value arecompared with the radial distance and velocity value obtained from thefirst result at 714. If the difference therebetween is greater than apredetermined value (e.g., determined based on a standard deviation),one or more of the PNL borehole model (706), the DAS borehole model(726), and/or the DDS borehole model (746) are updated, as at 732. Oneor more predictions from an updated PNL borehole model (706), DASborehole model (726), and/or DDS borehole model (746) are thenrecalculated.

If the difference is less than or equal to the predetermined value, asecond result is obtained, as at 734. The second result includes theradial distance of the one or more flow paths in the wellbore 102 andthe velocity of gas flow in the one or more flow paths as obtained fromany one of the PNL borehole model (706), the DAS borehole model (726),and/or the DDS borehole model (746).

At 762, a temperature profile is generated from the data obtained usingthe distributed temperature sensors (DDS) and, at 764, temperature dataincluding the temperature value at a given depth (e.g., the amplitude ofthe temperature profile at a given time), the temperature gradient (therate of increase in temperature with depth), and a derivative of thetemperature profile is obtained (e.g., via deconvolution) from thetemperature data. As at 770, data is obtained from a borehole staticmodel, and a DTS borehole model is created based on the data obtained,as at 766. This DTS borehole model may be similar to the DTS boreholemodel described above, and when provided with the temperature data, asat 765, the DTS borehole model (obtained at 766) determines a fourthradial distance of the one or more flow paths from center of thewellbore 102 and a fourth velocity value of the gas flow in each of theone or more flow paths, as at 768.

At 750, the fourth radial distance and the third velocity value arecompared with the radial distances and velocity values from the secondresult obtained at 734. If the difference therebetween is greater than apredetermined value, one or more of the PNL borehole model (706), theDAS borehole model (726), the DDS borehole model (746), and/or the DTSborehole model (766) are updated, as at 752. One or more predictionsfrom the updated model(s) PNL borehole model (706), noise log boreholemodel (726), Doppler borehole model (746), and the temperature boreholemodel (766) are recalculated. If the difference is less than or equal tothe predetermined value, the widths of the flow paths at the cementinterfaces, the velocity of the gas flow in each of the flow paths, andthe radial distance to the gas flow are obtained, as at 754.

Embodiments disclosed herein include:

A: A method that includes comprising conveying a tool string into awellbore at least partially lined with a first casing and a secondcasing concentrically overlapping a portion of the first casing, whereina first annulus is defined between the first and second casings andfilled with a first cement, and a second annulus is defined between thesecond casing and the wellbore and filled with a second cement,obtaining wellbore data from a pulsed neutron sensor included in thetool string and optical fiber measurements from one or more opticalfibers included in a cable positioned in the wellbore, determining a gaspresence in a flow path located at a cement interface in the wellboreand a first distance of the flow path from the tool string using apulsed neutron log borehole model and the wellbore data obtained fromthe pulsed neutron sensor, calculating a second distance of the flowpath from the tool string and a first velocity of the gas flow in theflow path using a distributed acoustic sensor (DAS) borehole model anddistributed acoustic sensing measurements obtained from the one or moreoptical fibers, correlating the first distance and the gas presence withthe second distance and the first velocity and thereby obtaining a firstcalculated distance of the flow path and a first calculated velocity ofthe gas flow, calculating a third distance of the flow path from thetool string and a second velocity of the gas flow in the flow path usinga distributed Doppler sensor (DDS) borehole model and distributedDoppler sensing measurements obtained from the one or more opticalfibers, comparing the third distance and the second velocity with thefirst calculated distance and the first calculated velocity,respectively, to obtain a second calculated distance of the flow pathand a second calculated velocity of the gas flow, calculating a fourthdistance of the flow path from the tool string and a third velocity ofthe gas flow in the flow path using a distributed temperature sensor(DTS) borehole model and distributed temperature sensing measurementsobtained from the one or more optical fibers, and comparing the fourthdistance and the third velocity with the second calculated distance andthe second calculated velocity, respectively, to determine a width ofthe cement interface, a distance of the cement interface from the toolstring, and a velocity of a gas flow in the cement interface.

B: A well system that includes a tool string and a cable positioned in awellbore drilled through one or more subterranean formations and atleast partially lined with a first casing and a second casingconcentrically overlapping a portion of the first casing, wherein afirst annulus is defined between the first and second casings and filledwith a first cement, a second annulus is defined between the secondcasing and the wellbore and filled with a second cement, the tool stringincludes a pulsed neutron sensor, and the cable includes one or moreoptical fibers used to obtain optical fiber measurements, and a dataacquisition system including a processor and a non-transitory computerreadable medium, the tool string and the cable communicatively coupledto the data acquisition system, and the computer readable medium storesa computer readable program code, when executed by the processor,configures the processor to operate the pulsed neutron sensor to obtainpulsed neutron log (PNL) data from the wellbore, determine a gaspresence in a flow path located at a cement interface in the wellboreand a first distance of the flow path from the tool string using apulsed neutron log borehole model and the PNL data, operate the dataacquisition system to obtain distributed acoustic sensing measurementsfrom the wellbore using the one or more optical fibers, calculate asecond distance of the flow path from the tool string and a firstvelocity of a gas flow in the flow path using a distributed acousticsensor (DAS) borehole model and the distributed acoustic sensingmeasurements, correlate the first distance and the gas presence with thesecond distance and the first velocity to obtain a first calculateddistance of the flow path and a first calculated velocity of the gasflow in the flow path, operate the data acquisition system to obtaindistributed Doppler sensing measurements from the wellbore using the oneor more optical fibers, calculate a third distance of the flow path fromthe tool string and a second velocity of the gas flow in the flow pathusing a distributed Doppler sensor (DDS) borehole model and thedistributed Doppler sensing measurements, compare the third distance andthe first calculated distance to obtain a second calculated distance ofthe flow path and compare the second velocity and the first calculatedvelocity to obtain a second calculated velocity of the gas flow, operatethe data acquisition system to obtain distributed temperature sensingmeasurements from the wellbore using the one or more optical fibers,calculate a fourth distance of the flow path from the tool string and athird velocity of the gas flow in the flow path using a distributedtemperature sensor (DTS) borehole model and the distributed temperaturesensing measurements, and compare the fourth distance and the thirdvelocity with the second calculated distance and the second calculatedvelocity, respectively, to determine a width of the cement interface, adistance of the cement interface from the tool string, and a velocity ofa gas flow in the cement interface.

Each of embodiments A and B may have one or more of the followingadditional elements in any combination: Element 1: wherein obtainingwellbore data from the pulsed neutron sensor comprises obtaining anamount of gas saturation in the flow path. Element 2: wherein obtainingthe optical fiber measurements from the one or more optical fiberscomprises one or more of obtaining amplitudes of noise signals detectedby the one or more optical fibers from the wellbore, obtaining afrequency spectrum of the noise signals, obtaining a relative phaseshift between the noise signals, obtaining frequency ratios of near andfar noise signals, and obtaining power spectral density of the noisesignals. Element 3: wherein obtaining the optical fiber measurementsfrom the one or more optical fibers comprises one or more of obtainingan amplitude and frequency information of an acoustic wave as modifiedby the wellbore, and obtaining a Doppler frequency shift between anacoustic wave emitted into the wellbore and the modified acoustic wave.Element 4: wherein obtaining the optical fiber measurements from the oneor more optical fibers comprises one or more of obtaining a temperatureof the wellbore, obtaining a temperature gradient of the wellbore, andobtaining a derivative of a temperature profile of the wellbore. Element5: further comprising updating at least one of the pulsed neutron logborehole model and the DAS borehole model when the gas presence in theflow path, the first distance of the flow path, the second distance ofthe flow path, and the first velocity of the gas flow do not conformwith each other. Element 6: further comprising recalculating one or moreof the gas presence in the flow path, the first distance of the flowpath, the second distance of the flow path, and the first velocity ofthe gas flow using a corresponding updated model. Element 7: furthercomprising updating one or more of the pulsed neutron log boreholemodel, the DAS borehole model, and the DDS borehole model when adifference between the first calculated distance and the third distanceand a difference between the first calculated velocity and the secondvelocity is greater than a predetermined value. Element 8: furthercomprising recalculating one or more of the gas presence in the flowpath, the first distance of the flow path, the second distance of theflow path, the first velocity of the gas flow, the third distance of theflow path, and the second velocity of the gas flow using a correspondingupdated model. Element 9: further comprising updating one or more of thepulsed neutron log borehole model, the DAS borehole model, the DDSborehole model, and the DTS borehole model when a difference between thesecond calculated distance and the fourth distance and a differencebetween the second calculated velocity and the third velocity is greaterthan a predetermined value. Element 10: further comprising recalculatingone or more of the gas presence in the flow path, the first distance ofthe flow path, the second distance of the flow path, the first velocityof the gas flow, the third distance of the flow path, the secondvelocity of the gas flow, the fourth distance of the flow path, and thethird velocity of the gas flow using a corresponding updated model.Element 11: further comprising obtaining the DTS borehole model from astatic borehole model.

Element 12: wherein the processor is further configured to update atleast one of the pulsed neutron log borehole model and the DAS boreholemodel when the gas presence in the flow path, the first distance of theflow path, the second distance of the flow path, and the first velocityof the gas flow do not conform with each other. Element 13: wherein theprocessor is further configured to recalculate one or more of the gaspresence in the flow path, the first distance of the flow path, thesecond distance of the flow path, and the first velocity of the gas flowusing a corresponding updated model. Element 14: wherein the processoris further configured to update one or more of the pulsed neutron logborehole model, the DAS borehole model, and the DDS borehole model whena difference between the first calculated distance and the thirddistance and a difference between the first calculated velocity and thesecond velocity is greater than a predetermined value. Element 15:wherein the processor is further configured to recalculate one or moreof the gas presence in the flow path, the first distance of the flowpath, the second distance of the flow path, the first velocity of thegas flow, the third distance of the flow path, and the second velocityof the gas flow using a corresponding updated model. Element 16: whereinthe processor is further configured to update one or more of the pulsedneutron log borehole model, the DAS borehole model, the DDS boreholemodel, and the DTS borehole model when a difference between the secondcalculated distance and the fourth distance and a difference between thesecond calculated velocity and the third velocity is greater than apredetermined value. Element 17: wherein the processor is furtherconfigured to recalculate one or more of the gas presence in the flowpath, the first distance of the flow path, the second distance of theflow path, the first velocity of the gas flow, the third distance of theflow path, the second velocity of the gas flow, the fourth distance ofthe flow path, and the third velocity of the gas flow using acorresponding updated model. Element 18: wherein the cable is locatedsuspending from the tool string or coupled to the exterior of at leastone of the first and second casings.

By way of non-limiting example, exemplary combinations applicable to Aand B include: Element 5 with Element 6; Element 7 with Element 8;Element 9 with Element 10; Element 12 with Element 13; Element 14 withElement 15; and Element 16 with Element 17.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope of the present disclosure. The systems and methodsillustratively disclosed herein may suitably be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series ofitems, with the terms “and” or “or” to separate any of the items,modifies the list as a whole, rather than each member of the list (i.e.,each item). The phrase “at least one of” allows a meaning that includesat least one of any one of the items, and/or at least one of anycombination of the items, and/or at least one of each of the items. Byway of example, the phrases “at least one of A, B, and C” or “at leastone of A, B, or C” each refer to only A, only B, or only C; anycombination of A, B, and C; and/or at least one of each of A, B, and C.

What is claimed is:
 1. A method, comprising: conveying a tool stringinto a wellbore, the wellbore at least partially lined with a firstcasing and a second casing concentrically overlapping a portion of thefirst casing, wherein a first annulus is defined between the first andsecond casings and filled with a first cement, and wherein a secondannulus is defined between the second casing and the wellbore and filledwith a second cement; obtaining wellbore data from a pulsed neutronsensor included in the tool string and optical fiber measurements fromone or more optical fibers included in a cable positioned in thewellbore; determining a gas presence in a flow path located at a cementinterface in the wellbore and a first distance of the flow path from thetool string using a pulsed neutron log borehole model and the wellboredata obtained from the pulsed neutron sensor; calculating a seconddistance of the flow path from the tool string and a first velocity ofthe gas flow in the flow path using a distributed acoustic sensor (DAS)borehole model and distributed acoustic sensing measurements obtainedfrom the one or more optical fibers; correlating the first distance andthe gas presence with the second distance and the first velocity andthereby obtaining a first calculated distance of the flow path and afirst calculated velocity of the gas flow; calculating a third distanceof the flow path from the tool string and a second velocity of the gasflow in the flow path using a distributed Doppler sensor (DDS) boreholemodel and distributed Doppler sensing measurements obtained from the oneor more optical fibers; comparing the third distance and the secondvelocity with the first calculated distance and the first calculatedvelocity, respectively, to obtain a second calculated distance of theflow path and a second calculated velocity of the gas flow; calculatinga fourth distance of the flow path from the tool string and a thirdvelocity of the gas flow in the flow path using a distributedtemperature sensor (DTS) borehole model and distributed temperaturesensing measurements obtained from the one or more optical fibers; anddetermining a width of the cement interface, a distance of the cementinterface from the tool string, and a velocity of a gas flow in thecement interface by comparing the fourth distance and the third velocitywith the second calculated distance and the second calculated velocity,respectively.
 2. The method of claim 1, wherein obtaining wellbore datafrom the pulsed neutron sensor comprises obtaining an amount of gassaturation in the flow path.
 3. The method of claim 1, wherein obtainingthe optical fiber measurements from the one or more optical fiberscomprises one or more of obtaining amplitudes of noise signals detectedby the one or more optical fibers from the wellbore, obtaining afrequency spectrum of the noise signals, obtaining a relative phaseshift between the noise signals, obtaining frequency ratios of near andfar noise signals, and obtaining power spectral density of the noisesignals.
 4. The method of claim 1, wherein obtaining the optical fibermeasurements from the one or more optical fibers comprises one or moreof obtaining amplitude and frequency information of an acoustic wave asmodified by the wellbore, and obtaining a Doppler frequency shiftbetween an acoustic wave emitted into the wellbore and the modifiedacoustic wave.
 5. The method of claim 1, wherein obtaining the opticalfiber measurements from the one or more optical fibers comprises one ormore of obtaining a temperature of the wellbore, obtaining a temperaturegradient of the wellbore, and obtaining a derivative of a temperatureprofile of the wellbore.
 6. The method of claim 1, further comprisingupdating at least one of the pulsed neutron log borehole model and theDAS borehole model when the gas presence in the flow path, the firstdistance of the flow path, the second distance of the flow path, and thefirst velocity of the gas flow do not conform with each other.
 7. Themethod of claim 6, further comprising recalculating one or more of thegas presence in the flow path, the first distance of the flow path, thesecond distance of the flow path, and the first velocity of the gas flowusing a corresponding updated model.
 8. The method of claim 1, furthercomprising updating one or more of the pulsed neutron log boreholemodel, the DAS borehole model, and the DDS borehole model when adifference between the first calculated distance and the third distanceand a difference between the first calculated velocity and the secondvelocity is greater than a predetermined value.
 9. The method of claim8, further comprising recalculating one or more of the gas presence inthe flow path, the first distance of the flow path, the second distanceof the flow path, the first velocity of the gas flow, the third distanceof the flow path, and the second velocity of the gas flow using acorresponding updated model.
 10. The method of claim 1, furthercomprising updating one or more of the pulsed neutron log boreholemodel, the DAS borehole model, the DDS borehole model, and the DTSborehole model when a difference between the second calculated distanceand the fourth distance and a difference between the second calculatedvelocity and the third velocity is greater than a predetermined value.11. The method of claim 10, further comprising recalculating one or moreof the gas presence in the flow path, the first distance of the flowpath, the second distance of the flow path, the first velocity of thegas flow, the third distance of the flow path, the second velocity ofthe gas flow, the fourth distance of the flow path, and the thirdvelocity of the gas flow using a corresponding updated model.
 12. Themethod of claim 1, further comprising obtaining the DTS borehole modelfrom a static borehole model.
 13. A well system, comprising: a toolstring and a cable positioned in a wellbore drilled through one or moresubterranean formations, wherein the wellbore is at least partiallylined with a first casing and a second casing concentrically overlappinga portion of the first casing, and wherein a first annulus is definedbetween the first and second casings and filled with a first cement,wherein a second annulus is defined between the second casing and thewellbore and filled with a second cement, wherein the tool stringincludes a pulsed neutron sensor, and wherein the cable includes one ormore optical fibers used to obtain optical fiber measurements; and adata acquisition system including a processor and a non-transitorycomputer readable medium, the tool string and the cable communicativelycoupled to the data acquisition system, wherein the computer readablemedium stores a computer readable program code that, when executed bythe processor, configures the processor to: operate the pulsed neutronsensor to obtain pulsed neutron log (PNL) data from the wellbore;determine a gas presence in a flow path located at a cement interface inthe wellbore and a first distance of the flow path from the tool stringusing a pulsed neutron log borehole model and the PNL data; operate thedata acquisition system to obtain distributed acoustic sensingmeasurements from the wellbore using the one or more optical fibers;calculate a second distance of the flow path from the tool string and afirst velocity of a gas flow in the flow path using a distributedacoustic sensor (DAS) borehole model and the distributed acousticsensing measurements; correlate the first distance and the gas presencewith the second distance and the first velocity to obtain a firstcalculated distance of the flow path and a first calculated velocity ofthe gas flow in the flow path; operate the data acquisition system toobtain distributed Doppler sensing measurements from the wellbore usingthe one or more optical fibers; calculate a third distance of the flowpath from the tool string and a second velocity of the gas flow in theflow path using a distributed Doppler sensor (DDS) borehole model andthe distributed Doppler sensing measurements; compare the third distanceand the first calculated distance to obtain a second calculated distanceof the flow path and compare the second velocity and the firstcalculated velocity to obtain a second calculated velocity of the gasflow; operate the data acquisition system to obtain distributedtemperature sensing measurements from the wellbore using the one or moreoptical fibers; calculate a fourth distance of the flow path from thetool string and a third velocity of the gas flow in the flow path usinga distributed temperature sensor (DTS) borehole model and thedistributed temperature sensing measurements; and determine a width ofthe cement interface, a distance of the cement interface from the toolstring, and a velocity of a gas flow in the cement interface bycomparing the fourth distance and the third velocity with the secondcalculated distance and the second calculated velocity, respectively.14. The system of claim 13, wherein the processor is further configuredto update at least one of the pulsed neutron log borehole model and theDAS borehole model when the gas presence in the flow path, the firstdistance of the flow path, the second distance of the flow path, and thefirst velocity of the gas flow do not conform with each other.
 15. Thesystem of claim 14, wherein the processor is further configured torecalculate one or more of the gas presence in the flow path, the firstdistance of the flow path, the second distance of the flow path, and thefirst velocity of the gas flow using a corresponding updated model. 16.The system of claim 13, wherein the processor is further configured toupdate one or more of the pulsed neutron log borehole model, the DASborehole model, and the DDS borehole model when a difference between thefirst calculated distance and the third distance and a differencebetween the first calculated velocity and the second velocity is greaterthan a predetermined value.
 17. The system of claim 16, wherein theprocessor is further configured to recalculate one or more of the gaspresence in the flow path, the first distance of the flow path, thesecond distance of the flow path, the first velocity of the gas flow,the third distance of the flow path, and the second velocity of the gasflow using a corresponding updated model.
 18. The system of claim 13,wherein the processor is further configured to update one or more of thepulsed neutron log borehole model, the DAS borehole model, the DDSborehole model, and the DTS borehole model when a difference between thesecond calculated distance and the fourth distance and a differencebetween the second calculated velocity and the third velocity is greaterthan a predetermined value.
 19. The system of claim 18, wherein theprocessor is further configured to recalculate one or more of the gaspresence in the flow path, the first distance of the flow path, thesecond distance of the flow path, the first velocity of the gas flow,the third distance of the flow path, the second velocity of the gasflow, the fourth distance of the flow path, and the third velocity ofthe gas flow using a corresponding updated model.
 20. The system ofclaim 13, wherein the cable is located suspending from the tool stringor coupled to the exterior of at least one of the first and secondcasings.